Hydrocarbon fluids, such as oil and natural gas, and other desirable formation fluids are obtained from a subterranean geologic formation, i.e., a reservoir, by drilling a well that penetrates the formation zone that contains the desired fluid Once a wellbore has been drilled, the well must be completed. A well “completion” involves the design, selection, and installation of equipment and materials in or around the wellbore for conveying, pumping, or controlling the production or injection of fluids. After the well has been completed, production of the formation fluids can begin.
When the subterranean formation is “soft” or poorly consolidated, small particulates (typically sand) present in the formation may dislodge and travel along with the produced fluid to the wellbore. Production of sand is highly undesirable since it erodes surface and subterranean equipment, and it must be removed from the produced fluids before they can be processed. In addition, the migrating sand can plug the flow channels in the formation and thereby necessitate other stimulation techniques, such as acid stimulation, to restore the well's performance.
Various methods have been employed to reduce or eliminate the concurrent production of sand and other particulates with the formation fluids. One common approach has been to filter the produced fluids through a gravel pack that has been placed into the wellbore Such gravel packs are often retained by a metal screen. The produced formation fluids travel through the permeable gravel pack (and the screen) before entering the wellbore. The sand and other particulates in the produced fluids are blocked by the gravel pack. This technique has been widely used in the past, but it has several disadvantages. With time, the gravel pack and the screen may be plugged by scale or particles, or badly eroded by the sand and other particulates in the produced fluids. This reduces the effectiveness of the gravel pack and screen and may actually shut down the production if the gravel pack and/or screen becomes plugged with sand or formation fines. In addition, the presence of the metal screen in the well inhibits reentry of drills and other tools into the wellbore and the metal screen can be difficult and costly to remove, which as led to the industry's development of so-called screenless completion techniques.
Many systems have been proposed for sand consolidation systems in oilfield applications but, to date, a completely satisfactory product has not been introduced and accepted by the industry. These techniques typically involve the injection of a consolidating fluid, such as a resin-based consolidating fluid, through the wellbore and into the formation surrounding the interval of interest. Resin-based consolidating fluids generally include an organic resin, a curing agent, a catalyst and an oil wetting agent. The resin system hardens in the formation, thereby consolidating it. Some systems chemicals are pumped in stages, creating a complicated treatment procedure. Most sand-consolidation techniques involve epoxy- or furan-based resins. Examples of such systems include those disclosed in U.S. Pat. Nos. 4,291,766, 4,427,069, 4,669,543, 5,199,492 and 5,805,593. When the individual components of the consolidating fluid are pumped as different stages into the formation they may or may not come together in the correct order, in the correct amounts, or they may not even come together at all. And, if they do come together, good mixing of the components is not assured Thus, there is no guarantee that after placement, the chemicals have been distributed evenly throughout the near-wellbore region. Because of the complexity and unreliability of these systems, single stage consolidation treatments have been long desired by the industry.
Thus far, single-stage consolidation systems have been directed toward screenless completions. Screenless completions involving formation consolidation were disclosed by Nelson et al. in U.S. Pat. No. 5,551,514. The concept in such systems was to consolidate the formation around perforations using a single-stage flexible gel system. Following the consolidation step, the formation permeability surrounding the treated interval is too low to allow the practical production of hydrocarbons. Therefore, the system required performing a fracturing/packing (“frac-pack”) treatment using curable resin coated proppant, or conventional proppant containing fibers, through the sand pack After the frac pack, the proppant pack in the perforations would prevent the entry of gravel into the wellbore, and the sand surrounding the perforations would be consolidated and unable to enter the wellbore. This disclosure envisioned the use of conventional resins; however, subsequent systems have used other chemical approaches.
James et al. disclosed a using a gel component and a gel forming agent as a sand consolidation medium for screenless completions in U.S. Pat. No. 6,450,260. Danican et al. disclosed the use of colloidal silica for formation consolidation in U.S. Pat. No. 7,013,973. The James patent had a drawback in that the consolidated sand pack was so impermeable that there were doubts whether one could fracture through it. In addition, diversion was difficult. The colloidal silica system also had diversion difficulties; however, the main problem with these systems was an incompatibility with brines. Frequently, highly saline completion fluids are present in the wellbore during sand-consolidation treatments.
More recently, U.S. Pat. No. 7,111,683 discloses a sand consolidation system based on silica and calcium hydroxide to cement sand grains together in the near-wellbore region. Silica and calcium hydroxide react to form a cementitious calcium silicate gel. This process is commonly known as a “pozzolanic reaction.” The greatest limitations of this technique involve separation of the chemical reagents from each other and from brines that are normally present in the wellbore. If the silica and calcium hydroxide contact each other before entering the sand pack, the reaction can begin prematurely in the wellbore. In addition, calcium hydroxide crystals tend to nucleate and grow, limiting their ability to penetrate the pores between sand grains. Also, if the silica component is deployed as colloidal silica, it will precipitate on contact with brine in the wellbore, thereby preventing sand consolidation.
Additionally, Feraud et al. (U.S. Pat. No. 6,613,720) discloses a wide range of controlled release techniques using emulsions. In this patent, the inventors disclosed controlled release of chemicals by stabilizing the active ingredients in the discontinuous phase of an emulsion, which is then destabilized by a number of different triggers.
It would be desirable to have a single-stage sand consolidation system and process for use in subterranean formations where the system contains stable ingredients and/or provides protection for the ingredients from each other and from brines, preventing undesirable crystal growth, precipitation or the like, which interfere with or even prevent sand consolidation.
It has now been discovered that an emulsion containing both silica and calcium hydroxide particles can be used as a single stage sand consolidation system without destabilization when the particles are isolated by placing them in different phases of the emulsion.